Wide temperature range cement retarder

ABSTRACT

According to an embodiment, a composition that can be used in cementing. The composition includes at least:
         (i) a hydraulic cement;   (ii) a copolymer comprising at least the monomeric units (a) through (d) of the following formula:       

                         
wherein the monomeric units (a) through (d) can be any sequence and any proportion in the copolymer. With water, the composition of the hydraulic cement and such a copolymer becomes a cement composition. According to the method, the cement composition is introduced into a well and allowed to set in the well.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable.

TECHNICAL FIELD

The inventions are in the field of producing crude oil or natural gasfrom subterranean formations. More specifically, the inventionsgenerally relate to cementing in oil or gas wells.

BACKGROUND ART

In the context of production from a well, oil and gas are understood torefer to crude oil and natural gas. Oil and gas are naturally occurringhydrocarbons in certain subterranean formations.

A subterranean formation is a body of rock that has sufficientlydistinctive characteristics and is sufficiently continuous forgeologists to describe, map, and name it. A subterranean formationhaving a sufficient porosity and permeability to store and transmitfluids is sometimes referred to as a reservoir. A subterranean formationcontaining oil or gas may be located under land or under the seabed offshore. Oil and gas reservoirs are typically located in the range of afew hundred feet (shallow reservoirs) to a few tens of thousands of feet(ultra-deep reservoirs) below the surface of the land or seabed.

To produce oil or gas, a well is drilled into a subterranean formationthat is an oil or gas reservoir. A well includes a wellhead and at leastone wellbore from the wellhead penetrating the earth.

Typically, a wellbore must be drilled hundreds or thousands of feet intothe earth to reach an oil or gas bearing formation. Generally, thegreater the depth of the formation the higher the static temperature andpressure of the formation.

Generally, well services include a wide variety of operations that maybe performed in oil, gas, geothermal, or water wells, such as drilling,cementing, completion, and intervention. These well services aredesigned to facilitate or enhance the production of desirable fluidssuch as oil or gas from or through a subterranean formation.

In general, drilling is the process of drilling the wellbore. After thehole is drilled, sections of steel pipe, referred to as casing, whichare slightly smaller in diameter than the borehole, are placed in atleast the uppermost portions of the wellbore. The casing providesstructural integrity to the newly drilled borehole.

Cementing is a common well operation. For example, cement compositionscan be used in cementing operations in which a string of pipe, such ascasing or liner, is cemented in a wellbore. After setting, the cementstabilizes the pipe in the wellbore and prevents undesirable migrationof fluids along the annulus between the wellbore and the outside of thecasing or liner between various zones of subterranean formationspenetrated by the wellbore. Where the wellbore penetrates into ahydrocarbon-bearing zone of a subterranean formation, the casing canlater be perforated to allow fluid communication between the zone andthe wellbore. The cemented casing also enables subsequent or remedialseparation or isolation of one or more production zones of the wellbore,for example, by using downhole tools such as packers or plugs, or byusing other techniques, such as forming sand plugs or placing cement inthe perforations. Cement compositions can also be utilized inintervention operations, such as in plugging highly permeable zones orfractures in zones that may be producing too much water, plugging cracksor holes in pipe strings, and the like.

After drilling and cementing the casing, completion is the process ofmaking a well ready for production or injection. This principallyinvolves preparing a zone of the wellbore to the requiredspecifications, running in the production tubing and associated downholeequipment, as well as perforating and stimulating as required.

Intervention is any operation carried out on a well during or at the endof its productive life that alters the state of the well or wellgeometry, provides well diagnostics, or manages the production of thewell. Workover can broadly refer to any kind of well intervention thatinvolves invasive techniques, such as wireline, coiled tubing, orsnubbing. More specifically, though, workover refers to the process ofpulling and replacing a completion.

A well service usually involves introducing a well fluid into a well. Asused herein, a “well fluid” is a fluid used in a well service. As usedherein, a “well fluid” broadly refers to any fluid adapted to beintroduced into a well for any purpose. A well fluid can be, forexample, a drilling fluid, a cement composition, a treatment fluid, or aspacer fluid. If a well fluid is to be used in a relatively smallvolume, for example less than about 200 barrels (32 m³), it is sometimesreferred to in the art as a wash, dump, slug, or pill.

Hydraulic cement is a material that when mixed with water hardens orsets over time because of a chemical reaction with the water. The cementcomposition sets by a hydration process, and it passes through a gelphase to solid phase. Because this is a chemical reaction with thewater, hydraulic cement is capable of setting even under water. Thehydraulic cement, water, and any other components are mixed to form acement composition in the initial state of slurry, which should be afluid for a sufficient time before setting for pumping the compositioninto the wellbore and for placement in a desired downhole location inthe well.

In performing cementing, a cement composition is pumped as a fluid(typically in the form of suspension or slurry) into a desired locationin the wellbore. For example, in cementing a casing or liner, the cementcomposition is pumped into the annular space between the exteriorsurfaces of a pipe string and the borehole (that is, the wall of thewellbore). The cement composition is allowed time to set in the annularspace, thereby forming an annular sheath of hardened, substantiallyimpermeable cement. The hardened cement supports and positions the pipestring in the wellbore and fills the annular space between the exteriorsurfaces of the pipe string and the borehole of the wellbore.

It is important to maintain a cement in a pumpable slurry state until itplaced in a desired portion of the well. For this purpose, a cementretarder, which is sometimes referred to as a set retarder or simply aretarder, can be used in a cement composition. A retarder retards thesetting process and helps provide adequate pumping time to place thecement slurry.

Without being limited by any theory, it is believed a retarder works byone or more of the principles of chelation, adsorption, orprecipitation.

In general, the selection of a cement retarder depends upon the welltemperature. In addition, different thickening time can be achieved atparticular temperature by varying the concentration of the retarder inthe cement composition. Some of the known retarders work at a lowtemperature range while others work at high temperature range.

Phosphonate retarders are known to work at high temperature (450° F. to550° F.) as described in CA1258366. Borates (e.g., sodium pentaborateand potassium pentaborate) and organic acids (e.g., citric acid andtartaric acid) are used as retarder or intensifier for high temperature.Similarly, polymeric retarder containing phosphate groups has beendescribed in GB2443923 to work at temperature 300° F. to 600° F. Theseretarders are not desirable for low temperature application, however,because they are too sensitive to concentration. A slight inadvertentchange in concentration during field operation may adversely affect thethickening time. It is desirable to have a retarder which performs wellat low as well as high temperature, including by not being too sensitiveto concentration at the design temperature.

It would be desirable to have a single polymer that could be used tohelp control the thickening time of a cement composition over a widerange of temperatures and without being too sensitive to concentrationin the cement composition over the wide range of temperatures.

SUMMARY OF THE INVENTION

According to an embodiment, a composition is provided that can be usedin cementing. The composition includes at least:

(i) a hydraulic cement; and

(ii) a copolymer comprising at least the monomeric units (a) through (d)of the following formula:

wherein the monomeric units (a) through (d) can be any sequence and anyproportion in the copolymer. With water, the composition of thehydraulic cement and such a copolymer becomes a cement composition.

According to another embodiment of the invention, a method of cementingin a well is provided. The method includes the steps of:

(A) introducing a cement composition into the well, the cementcomposition comprising:

-   -   (i) a hydraulic cement;    -   (ii) a copolymer comprising at least the monomeric units (a)        through (d) of the following formula:

-   -   wherein the monomeric units (a) through (d) can be any sequence        and any proportion in the copolymer; and        -   (iii) water; and    -   (B) allowing the cement composition to set in the well.

These and other aspects of the invention will be apparent to one skilledin the art upon reading the following detailed description. While theinvention is susceptible to various modifications and alternative forms,specific embodiments thereof will be described in detail and shown byway of example. It should be understood, however, that it is notintended to limit the invention to the particular forms disclosed, but,on the contrary, the invention is to cover all modifications andalternatives falling within the spirit and scope of the invention asexpressed in the appended claims.

BRIEF DESCRIPTION OF THE DRAWING

The accompanying drawing is incorporated into the specification to helpillustrate examples according to the presently most-preferred embodimentof the invention.

FIG. 1 is a graph showing the effect of the copolymer concentration onthickening time at 120° F.

FIG. 2 is a graph showing the effect of the copolymer concentration onthickening time at 217° F.

DETAILED DESCRIPTION OF PRESENTLY PREFERRED EMBODIMENTS AND BEST MODEDefinitions and Usages

Interpretation

The words or terms used herein have their plain, ordinary meaning in thefield of this disclosure, except to the extent explicitly and clearlydefined in this disclosure.

If there is any conflict in the usages of a word or term in thisdisclosure and one or more patent(s) or other documents that may beincorporated by reference, the definitions that are consistent with thisspecification should be adopted.

Patent Terms

The words “comprising,” “containing,” “including,” “having,” and allgrammatical variations thereof are intended to have an open,non-limiting meaning. For example, a composition comprising a componentdoes not exclude it from having additional components, an apparatuscomprising a part does not exclude it from having additional parts, anda method having a step does not exclude it having additional steps. Whensuch terms are used, the compositions, apparatuses, and methods that“consist essentially of” or “consist of” the specified components,parts, and steps are specifically included and disclosed.

The indefinite articles “a” or “an” mean one or more than one of thecomponent, part, or step that the article introduces.

Whenever a numerical range of degree or measurement with a lower limitand an upper limit is disclosed, any number and any range falling withinthe range is also intended to be specifically disclosed. For example,every range of values (in the form “from a to b,” or “from about a toabout b,” or “from about a to b,” “from approximately a to b,” and anysimilar expressions, where “a” and “b” represent numerical values ofdegree or measurement) is to be understood to set forth every number andrange encompassed within the broader range of values.

Terms such as “first,” “second,” “third,” etc. are assigned arbitrarilyand are merely intended to differentiate between two or more components,parts, or steps that are otherwise similar or corresponding in nature,structure, function, or action. For example, the words “first” and“second” serve no other purpose and are not part of the name ordescription of the following name or descriptive terms. The mere use ofthe term “first” does not require that there be any “second” similar orcorresponding component, part, or step. Similarly, the mere use of theword “second” does not require that there by any “first” or “third”similar or corresponding component, part, or step. Further, it is to beunderstood that the mere use of the term “first” does not require thatthe element or step be the very first in any sequence, but merely thatit is at least one of the elements or steps. Similarly, the mere use ofthe terms “first” and “second” does not necessarily require anysequence. Accordingly, the mere use of such terms does not excludeintervening elements or steps between the “first” and “second” elementsor steps, etc.

Well Terms

A “subterranean formation” is a body of rock that has sufficientlydistinctive characteristics and is sufficiently continuous forgeologists to describe, map, and name it.

A subterranean formation having a sufficient porosity and permeabilityto store and transmit fluids is sometimes referred to as a “reservoir.”

A “well” includes a wellhead and at least one wellbore from the wellheadpenetrating the earth. The “wellhead” is the surface termination of awellbore, which surface may be on land or on a seabed. A “well site” or“job site” is the geographical location of a wellhead of a well. It mayinclude related facilities, such as a tank battery, separators,compressor stations, heating or other equipment, and fluid pits. Ifoffshore, a well site can include a platform.

The “wellbore” refers to the drilled hole, including any cased oruncased portions of the well. The “borehole” usually refers to theinside wellbore wall, that is, the rock face or wall that bounds thedrilled hole. A wellbore can have portions that are vertical,horizontal, or anything in between, and it can have portions that arestraight, curved, or branched. As used herein, “uphole,” “downhole,” andsimilar terms are relative to the direction of the wellhead, regardlessof whether a wellbore portion is vertical or horizontal.

As used herein, introducing “into a well” means introduced at least intoand through the wellhead. According to various techniques known in theart, tubulars, equipment, tools, or well fluids can be directed from thewellhead into any desired portion of the wellbore. Additionally, a wellfluid can be directed from a portion of the wellbore into the rockmatrix of a zone.

As used herein, the word “tubular” means any kind of pipe. Examples oftubulars include, but are not limited to, a drill pipe, a casing, atubing string, a line pipe, and a transportation pipe. Tubulars can alsobe used to transport fluids into or out of a subterranean formation,such as oil, gas, water, liquefied methane, coolants, and heated fluids.For example, a tubular can be placed underground to transport producedhydrocarbons or water from a subterranean formation to another location.

As used herein, the term “annulus” means the space between two generallycylindrical objects, one inside the other, where fluid can flow. Theobjects can be concentric or eccentric. One of the objects can be atubular and the other object can be an enclosed conduit. The enclosedconduit can be a wellbore or borehole or it can be another tubular. Thefollowing examples illustrate some situations in which an annulus canexist, but are in no way limiting as to all the situations in which anannulus can exist. Referring to an oil, gas, or water well, in an openhole well, the space between the wellbore and the outside of a tubingstring is an annulus. In a cased hole, the space between the wellboreand the outside of the casing is an annulus. Also, in a cased hole,there may be an annulus between the tubing string and the inside of thecasing.

As used herein, a “well fluid” broadly refers to any fluid adapted to beintroduced into a well for any purpose. A well fluid can be, forexample, a drilling fluid, a cement composition, a treatment fluid, or aspacer fluid. If a well fluid is to be used in a relatively smallvolume, for example less than about 200 barrels (about 32 m³), it issometimes referred to in the art as a wash, dump, slug, or pill.

Broadly, a zone refers to an interval of rock along a wellbore that isdifferentiated from uphole and downhole zones based on hydrocarboncontent or other features, such as permeability, composition,perforations or other fluid communication with the wellbore, faults, orfractures. A zone of a wellbore that penetrates a hydrocarbon-bearingzone that is capable of producing hydrocarbon is referred to as a“production zone.” As used herein, a “treatment zone” refers to aninterval of rock along a wellbore into which a well fluid is directed toflow from the wellbore.

The term “design temperature” refers to an estimate or measurement ofthe actual temperature at the down hole environment at the time of awell treatment. That is, design temperature takes into account not onlythe bottom hole static temperature (“BHST”), but also the effect of thetemperature of the well fluid on the BHST during treatment, which is thebottom hole circulation temperature (“BHCT”). Because treatment fluidsmay be considerably cooler than BHST, the difference between the twotemperatures can be quite large. Ultimately, if left undisturbed, asubterranean formation will return to the BHST.

Fluid Terms

The physical state or phase of a substance (or mixture of substances)and other physical properties are determined at a temperature of 77° F.(25° C.) and a pressure of 1 atmosphere (Standard Laboratory Conditions)without any applied shear.

As used herein, a fluid is a substance that behaves as a fluid underStandard Laboratory Conditions.

Every fluid inherently has at least a continuous phase. A fluid can havemore than one phase. The continuous phase of a well fluid is a liquidunder standard laboratory conditions. For example, a well fluid can inthe form of be a suspension (solid particles dispersed in a liquidphase), an emulsion (liquid particles dispersed in another liquidphase), or a foam (a gas phase dispersed in liquid phase).

Unless otherwise specified, the apparent viscosity of a fluid (excludingany suspended solid particulate larger than silt) is measured with aFann Model 50 type viscometer using an R1 rotor, B1 bob, and F1 torsionspring at a shear rate of 40 l/s, and at a temperature of 77° F. (25°C.) and a pressure of 1 atmosphere. For reference, the viscosity of purewater is about 1 cP.

Cement Compositions

As used herein, a “cement composition” is a mixture of at leasthydraulic cement and water. The cement composition can also includeadditives.

As used herein, the term “cement” means a dry particulate (e.g., powder)substance that acts as a binder to bind other materials together. A“hydraulic cement” (e.g., Portland cement) hardens because of hydration,chemical reactions. As used herein, “cement” means hydraulic cementunless otherwise specified.

During well completion, it is common to introduce a cement compositioninto an annulus in the wellbore. For example, in a cased hole, thecement composition is placed into and allowed to set in the annulusbetween the wellbore and the casing in order to stabilize and secure thecasing in the wellbore. After setting, the set cement composition shouldhave a low permeability. Consequently, oil or gas can be produced in acontrolled manner by directing the flow of oil or gas through the casingand into the wellhead. Cement compositions can also be used inwell-plugging operations or gravel-packing operations.

During cementing operations, it is necessary for the cement compositionto remain pumpable during introduction into the subterranean formationor the well and until the cement composition is situated in the portionof the subterranean formation or the well to be cemented. After thecement composition has reached the portion of the well to be cemented,the cement composition ultimately sets. A cement composition thatthickens too quickly while being pumped can damage pumping equipment orblock tubing or pipes, and a cement composition that sets too slowly cancost time and money while waiting for the cement composition to set.

As used herein, a “retarder” is a chemical agent used to increase thethickening time of a hydraulic cement composition. The thickening timerequired for a cement composition tends to increase with depth of thezone to be cemented due to the greater time required to complete thecementing operation and the effect of increased temperature on thethickening time of the cement. A longer thickening time at the designtemperature allows for a longer pumping time that may be required.

Hydraulic Cement and Cementitious Materials

A hydraulic cement hardens by reaction with water. A hydraulic cementcan be used to make cementitious materials that can thicken and set whenmixed with water. Cementitious materials include, but are not limitedto, Portland cements (e.g., classes A, B, C, G, and H Portland cements),pozzolanic cements, gypsum cements, phosphate cements, high aluminacontent cements, silica cements, shale cements, acid/base cements,magnesia cements such as Sorel cements, zeolite cement systems, cementkiln dust cement systems, slag cements, micro-fine cement, metakaolin,and combinations thereof.

Copolymer as Retarder

The present invention discloses a type of polymer that works as a cementretarder over a wide range of temperatures and without being toosensitive to concentration in the cement composition over the wide rangeof temperatures. According to the invention, the polymer has bothcarboxylic and phosphinic acid functional groups. Without being limitedby any theory, it is believed that a polymer having both such functionalgroups provides the necessary retarder function over a wide range oftemperatures without excessive sensitivity to concentration.

A retarder according to the invention is a copolymer including at leastthe functional groups of carboxylic acid, sulfonic acid or sulfonic acidsalt, hydroxyl, and phosphinic acid. A structure of the polymer can begenerally represented by the following chemical formula including atleast the monomeric units (a) through (d), wherein the monomers formingthe polymer can be any sequence in the copolymer:

Most preferably, the copolymer consists essentially of the monomericunits (a) through (d).

The monomeric units can be in any proportion. Preferably, the monomericunits (a) through (d) of a copolymer according to the invention are inthe following proportions: wherein the monomeric units (a) through (d)in the copolymer are in the following proportionate ranges: (a) is inthe range of 65 to 75% by weight; (b) is in the range of 10 to 15% byweight; (c) is in the range of 10 to 15% by weight; and (d) is in therange of 3 to 7% by weight.

The polymer can be synthesized by addition polymerization in bulk or insolution using suitable solvent(s). For example, the free radicalcopolymerization of one or more monomers containing the functionalgroups of carboxylic acid, sulfonic acid or salt of sulfonic acid, andhydroxyl group in the presence of a chain transfer agent that is capableproviding a phosphinic acid group would provide such a copolymer. Anexample of a method of making such a polymer is disclosed in U.S. Pat.No. 5,077,361 issued Dec. 31, 1991, entitled “Low Molecular Weight WaterSoluble Phosphinate and Phosphonate Containing Polymers,” which isincorporated herein by reference in its entirety.

Monomers containing a carboxylic acid group include, for example,acrylic acid, methacrylic acid, vinyl acetic acid, itaconic acid, maleicacid, fumaric acid, and citraconic acid.

Monomers containing a sulfonic acid group include, for example,2-acrylamido-2-methyl propane sulfonic acid, styrene sulfonic acid, andtheir salts.

Monomers containing a hydroxyl group include, for example,2-hydroxyethyl methacrylate, 2-hydroxypropyl methacrylate,2-hydroxyethyl acrylate, and 2-hydroxypropyl acrylate.

The chain transfer agent capable of providing a phosphinic acid groupcan be, for example, hypophosphorous acid.

Most preferably, the monomeric units (a) through (d) are acrylic acid,2-acrylamido-2-methylpropane sulfonic acid sodium salt, 2-hydroxypropylacrylate, and phosphinic acid, respectively.

A retarder according to this invention has been demonstrated to performwell at low temperatures (100° F. to 220° F.) as well as hightemperatures (300° F. to 400° F.). The retarder is not over sensitive toconcentration, especially at low temperature, which is desirable fordesigning cement slurry formulations in the field. For the temperaturerange from 220° F. to 300° F. and for greater than 400° F., a retarderintensifier can be used. An example of a retarder intensifier is anon-lignin, carboxylic acid cement retarder, which is tartaric acid.

Aqueous Phase

According to the invention, an aqueous phase can be present in theamount from about 20 to about 180 percent by weight of cement,alternatively from about 28 to about 66 percent by weight of cement,alternatively from about 36 to about 60 percent by weight of cement.

It is recognized that, in general, for water to be suitable for use in awell fluid, usually all that is required is that the water does notcontain one or more materials that would be particularly detrimental tothe chemistry of the cement composition or detrimental to downholeequipment or the subterranean formation.

The aqueous phase can include freshwater or non-freshwater.Non-freshwater sources of water can include surface water ranging frombrackish water to seawater, brine, returned water (sometimes referred toas flowback water) from the delivery of a well fluid into a well, unusedwell fluid, and produced water. As used herein, brine refers to waterhaving at least 40,000 mg/L total dissolved solids.

Additives

Cement composition can contain additives. Such additives may include butnot limited to resins, latex, stabilizers, silica, microspheres, aqueoussuperabsorbers, viscosifying agents, suspending agents, dispersingagents, salts, accelerants, surfactants, retardants, defoamers,high-density materials, low-density materials, fluid loss controlagents, elastomers, vitrified shale, gas migration control additives,formation conditioning agents, or other additives or modifying agents,and/or combinations thereof.

Method Steps

A cement composition can be prepared at the well site, prepared at aplant or facility prior to use, or certain components can be pre-mixedprior to use and then transported to the well site. Certain componentsof the treatment fluid may be provided as a “dry mix” to be combinedwith other components prior to or during introducing into the well.

In certain embodiments, the preparation of a cement compositionaccording to the present invention can be done at the well site in amethod characterized as being performed “on the fly.” The term“on-the-fly” includes methods of combining two or more componentswherein a flowing stream of one element is continuously introduced intoflowing stream of another component so that the streams are combined andmixed while continuing to flow as a single stream as part of theon-going treatment. Such mixing can also be described as “real-time”mixing.

As used herein, introducing “into a well” means introduced at least intoand through the wellhead. According to various techniques known in theart, equipment, tools, or well fluids can be directed from the wellheadinto any desired portion of the wellbore. Additionally, a well fluid canbe directed from a portion of the wellbore into the rock matrix of azone.

As used herein, “into a treatment zone” means into and through thewellhead and, additionally, through the wellbore and into the treatmentzone.

Often the step of delivering a well fluid into a well is within arelatively short period after forming the well fluid, e.g., less within30 minutes to one hour. More preferably, the step of delivering the wellfluid is immediately after the step of forming the well fluid, which is“on the fly.”

It should be understood that the step of delivering a well fluid into awell can advantageously include the use of one or more fluid pumps.

In an embodiment, after the step of introducing, the method includes thestep of allowing time for the cement composition to set in the well.

Preferably, after the step of allowing time for setting, the methodincludes a step of producing oil or gas from the well.

Pumping Time

As used herein, the “pumping time” is the total time required forpumping a hydraulic cement composition into a desired portion or zone ofthe well, plus a safety factor, in a cementing operation.

Thickening Time

As used herein, the “thickening time” is how long it takes for a cementcomposition to become unpumpable at a specified temperature andspecified pressure. The pumpability of a cement composition is relatedto the consistency of the composition. The consistency of a cementcomposition is measured in Bearden units of consistency (Bc), adimensionless unit with no direct conversion factor to the more commonunits of viscosity. As used herein, a cement composition becomes“unpumpable” when the consistency of the composition reaches 70 Bc.

As used herein, the consistency of a cement composition is measuredaccording to ANSI/API Recommended Practice 10B-2 as follows. The cementcomposition is mixed. The cement composition is then placed in the testcell of a High-Temperature, High-Pressure (HTHP) consistometer, such asa Fann Model 275 or a Chandler Model 8240. The cement composition istested in the HTHP consistometer at the specified temperature andpressure. Consistency measurements are taken continuously until theconsistency of the cement composition exceeds 70 Bc.

Of course, the thickening time should be greater than the designedpumping time for a cementing operation.

Setting and Compressive Strength

As used herein, the term “set” is intended to mean the process ofbecoming hard or solid by curing. Depending on the cement compositionand conditions, it can take a few minutes to 72 hours or longer for somecement compositions to initially set. A cement composition sample thatis at least initially set is suitable for destructive compressivestrength testing and permeability testing. Some cement compositions cancontinue to develop a compressive strength greater than 50 psi over thecourse of several days. The compressive strength of certain kinds ofcement compositions can reach over 10,000 psi.

The compressive strength of a cement composition can be used to indicatewhether the cement composition has set. As used herein, a cementcomposition is considered “initially set” when the cement compositionhas developed a compressive strength of 50 psi using the non-destructivecompressive strength method. As used herein, the “initial setting time”is the time between when the cement is added to the water and when thecement composition is initially set. If not otherwise stated, thesetting and the initial setting time is determined at a temperature of212° F. and a pressure of 3,000 psi.

Compressive strength is generally measured at a specified time after thecement composition has been mixed and then cured at a specifiedtemperature and pressure. For example, compressive strength can bemeasured at a time in the range of about 24 to about 48 hours at atemperature of 212° F. According to ANSI/API Recommended Practice 10B-2,compressive strength can be measured by either a destructive method ornon-destructive method.

The destructive method mechanically tests the strength of cementcomposition samples at various points in time by crushing the samples ina compression-testing machine. The destructive method is performed asfollows. The cement composition is mixed. Then, the mixed composition iscured. The cured cement composition sample is placed in a compressivestrength testing device, such as a Super L Universal testing machinemodel 602, available from Tinius Olsen, Horsham in Pa., USA. Accordingto the destructive method, the compressive strength is calculated as theforce required to break the sample divided by the smallestcross-sectional area in contact with the load-bearing plates of thecompression device. The actual compressive strength is reported in unitsof pressure, such as pound-force per square inch (psi) or megapascals(MPa).

The non-destructive method continually measures a correlated compressivestrength of a cement composition sample throughout the test period byutilizing a non-destructive sonic device such as an Ultrasonic CementAnalyzer (UCA) available from Fann Instruments in Houston, Tex. As usedherein, the “compressive strength” of a cement composition is measuredutilizing an Ultrasonic Cement Analyzer as follows. The cementcomposition is mixed. The cement composition is placed in an UltrasonicCement Analyzer, in which the cement composition is heated to thespecified temperature and pressurized to the specified pressure. The UCAcontinually measures the transit time of the acoustic signal through thesample. The UCA device contains preset algorithms that correlate transittime to compressive strength. The UCA reports the compressive strengthof the cement composition in units of pressure, such as psi ormegapascals (MPa).

Mixing Conditions

As used herein, if any test (e.g., thickening time or compressivestrength) requires mixing to form the cement composition, then themixing step is performed according to ANSI/API Recommended Practice10B-2 as follows. Any of the ingredients that are a dry substance arepre-blended. The liquid is added to a mixing container and the containeris then placed on a mixer base. For example, the mixer can be aLightning Mixer. The motor of the base is then turned on and maintainedat about 4,000 revolutions per minute (rpm). The cement and any otherpre-blended dry ingredients are added to the container at a uniform ratein not more than 15 seconds (s). After all the cement and any otheringredients have been added to the water in the container, a cover isthen placed on the container, and the cement composition is mixed at12,000 rpm (+/−500 rpm) for 35 s (+/−1 s). It is to be understood thatthe cement composition is mixed under standard laboratory conditions(about 77° F. and about 1 atmosphere pressure).

Curing Conditions

As used herein, if any test (e.g., compressive strength) requires curingthe cement composition, then the curing step is performed according toANSI/API Recommended Practice 10B-2 as follows. After the cementcomposition has been mixed, the cement composition is poured into acuring mould. The curing mould is placed into a curing chamber and thecuring chamber is maintained at the specified temperature and pressurefor the specified time. After the specified time, the curing mould isplaced into a water cooling bath at about room temperature to cool thecement composition sample.

Temperature and Pressure Conditions

It is also to be understood that if any test (e.g., thickening time orcompressive strength) specifies that a step of the test be performed ata specified temperature and a specified pressure, then after being mixedunder Standard Laboratory Conditions, the temperature and pressure ofthe cement composition is ramped up to the specified temperature andpressure. For example, the cement composition can be mixed at 77° F. andthen placed into the testing apparatus and the temperature of the cementcomposition can be ramped up to the specified temperature. As usedherein, the rate of ramping up the temperature is in the range of about3° F.,/min to about 5° F./min. After the cement composition is ramped upto the specified temperature and pressure, the cement composition ismaintained at that temperature and pressure for the specified duration.

EXAMPLES

To facilitate a better understanding of the present invention, thefollowing examples of certain aspects of some embodiments are given. Inno way should the following examples be read to limit, or define, theentire scope of the invention.

The effect of copolymer as described herein on cement slurry wasinvestigated. A copolymer comprising acrylic acid,2-acrylamido-2-methylpropane sulfonic acid sodium salt, 2-hydroxypropylacrylate, and phosphinic acid was tested at various concentration andtemperature. The copolymer is an aqueous solution containing 35.1%solid. The structure and composition of the copolymer is given below.

The monomeric units of this tested copolymer are in the followingproportions: (a)=65-75%, (b)=10-15%, (c)=10-15%, d=3-7% by weight.

A cement composition was prepared of this copolymer as retarder, 100 wt.% class H cement, 46.5 wt. % water, 35 wt. % coarse silica flour as astrength retrogression preventive additive, and 0.5 wt. % sulfonic acidcopolymer as a fluid loss control additive. These weight percentagesgiven are by weight of cement (“BWOC”).

TABLE 1 Composition of the cement slurry (Density: 16.58 ppg) MaterialsAmount (%) Water 46.5 Class H Cement 100 Silica Flour 35 Fluid lossadditive 0.5

The thickening times of the cement slurry as a function of temperatureand the concentration of copolymer was determined. These results arepresented in Table 2. The results at temperatures 120° F. and 217° F.are plotted in the charts of FIG. 1 and FIG. 2.

TABLE 2 Effect of copolymer concentration on thickening time TemperatureCopolymer Concentration Thickening time (° F.) (%) (HR:MM) 100 0.08 3:45120 0.08 3:19 0.12 5:41 0.16 7:40 150 0.13 4:22 180 0.26 6:11 217 0.262:56 0.39 7:43 0.52 9:47 270 0.52* 3:38 330 0.9 6:20 1.3 8:18 360 1.84:53 *0.5% tartaric acid

TABLE 3 Compressive strength of slurry with retarder Time for Time for24 hrs Retarder Thickening 50 psi 500 psi compressive (%) Time (HR:MM)(HR:MM) (HR:MM) strength (psi) 0.26 2:56  8:36  9:30 3261 0.52 9:4715:12 17:36 2349

TABLE 4 Rheology of the slurry Fann 35 Viscometer Reading (at 75° F.)Retarder (%) 3 6 100 200 300 600 0 2 6 73 133 187   300+ 0.26 2 4 54 97178 255

CONCLUSION

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein.

The particular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. It is, therefore, evident that theparticular illustrative embodiments disclosed above may be altered ormodified and all such variations are considered within the scope andspirit of the present invention.

The various elements or steps according to the disclosed elements orsteps can be combined advantageously or practiced together in variouscombinations or sub-combinations of elements or sequences of steps toincrease the efficiency and benefits that can be obtained from theinvention.

The invention illustratively disclosed herein suitably may be practicedin the absence of any element or step that is not specifically disclosedor claimed.

Furthermore, no limitations are intended to the details of compositionor steps, other than as described in the claims.

What is claimed is:
 1. A method of cementing in a well, the method comprising the steps of: (A) introducing a cement composition into the well, the cement composition comprising: (i) a hydraulic cement; (ii) a copolymer comprising at least the monomeric units (a) through (d) of the following formula:

wherein the monomeric units (a) through (d) can be in any sequence in the copolymer; and (iii) water; and (B) allowing the cement composition to set in the well.
 2. The method according to claim 1, wherein the hydraulic cement is a cementitious material selected from the group consisting of Portland cements, pozzolanic cements, gypsum cements, phosphate cements, high alumina content cements, silica cements, high alkalinity cements, shale cements, acid/base cements, magnesia cements, fly ash cement, zeolite cement systems, cement kiln dust cement systems, slag cements, micro-fine cement, metakaolin, or combinations thereof.
 3. The method according to claim 1, wherein the monomeric units (a) through (d) are acrylic acid, 2-acrylamido-2-methylpropane sulfonic acid sodium salt, 2-hydroxypropyl acrylate, and phosphinic acid, respectively.
 4. The method according to claim 1, wherein the monomeric units (a) through (d) in the copolymer are in the following ranges: (a) is in the range of 65 to 75% by weight; (b) is in the range of 10 to 15% by weight; (c) is in the range of 10 to 15% by weight; and (d) is in the range of 3 to 7% by weight.
 5. The method according to claim 1, wherein the concentration of the copolymer is between 0.05% by weight of the cement and 3% by weight of the cement.
 6. The method according to claim 1, wherein the cement composition further comprises silica flour.
 7. The method according to claim 1, further comprising a fluid-loss control additive.
 8. The method according to claim 7, wherein the fluid-loss control additive is selected from the group consisting of: sulfonic acid copolymer, acrylamide copolymers, cellulosic polymers and derivatives thereof, and modified cellulosic polymers.
 9. The method according to claim 1, further comprising a retarder intensifier.
 10. The method according to claim 9, wherein the retarder intensifier is tartaric acid.
 11. The method according to claim 10, wherein the composition has a thickening time of at least 2 hours at any temperature between 100° F. and 360° F.
 12. A method of cementing in a well, the method comprising the steps of: (A) introducing a cement composition into the well, the cement composition comprising: (i) a hydraulic cement; (ii) a copolymer comprising at least the monomeric units (a) through (d) of the following formula:

wherein the monomeric units (a) through (d) can be in any sequence in the copolymer, and wherein the monomeric units (a) through (d) in the copolymer are in the following ranges: (a) is in the range of 65 to 75% by weight; (b) is in the range of 10 to 15% by weight; (c) is in the range of 10 to 15% by weight; (d) is in the range of 3 to 7% by weight; and (iii) water; and (B) allowing the cement composition to set in the well. 